GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

Final Report 

BART Analysis for 

Healy Power Plant 

Prepared For: 

Golden Valley Electric Association 

Fairbanks, Alaska 

January 2009 

Prepared By: 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-1 

Executive Summary 

Background 

In response to the Regional Haze Rule and Best Available Retrofit Technology (BART) 

regulations and guidelines, CH2M HILL was requested to perform a BART analysis for 

Golden Valley Electric Association, Inc. (GVEA) Healy Power Plant. Unit 1 (hereafter 

referred to as Healy 1) and Auxiliary Boiler #1 are considered BART sources. 

The Alaska Department of Conservation (ADEC) has determined that the GVEA Healy 

Power Plant is subject to BART evaluation because it was built in the time period covered by 

the rule (1962-1977) and has been shown through modeling to have a greater than 

0.5 deciview (dV) visibility impact at Denali National Park and Preserve (DNPP), a federal 

Class I area. ADEC determined that oxides of nitrogen (NOx) emissions were the primary 

contributor to visibility impairment; however, BART analyses for sulfur dioxide (SO2) and 

particulate matter (PM) were also required by the agency. 

For Healy Unit 1, a BART analysis has been conducted for the following criteria pollutants: 

NOx, SO2, and particulate matter less than 10 microns in aerodynamic diameter (PM10). For 

Auxiliary Boiler #1, there were essentially no visibility impacts, and no controls analysis 

was conducted. 

The U. S. Environmental Protection Agency (EPA) BART guidelines provide presumptive 

BART emission limits whereas units emitting at or below the presumptive limits are 

considered to meet BART. These presumptive levels, however, are typically applicable to 

large units over 200 megawatts (MW) at 750-MW facilities., Since presumptive BART 

limits have not been prescribed for extremely small units such as Healy, however, the 

presumptive BART limits found in the BART guidelines have been used as a general guide 

in evaluating potential control options. BART emissions limits must be achieved within 

5 years after the State Implementation Plan (SIP) is approved by the EPA, and a compliance 

date of 2014 was assumed for this analysis. 

Healy Unit 1 is a 25-MW boiler equipped with pollutant controls for NOx, SO2 and PM10. 

Controls currently in place include low NOx burners (LNB) with over fire air (OFA), dry 

sorbent flue gas desulfurization (FGD) and a baghouse. 

In completing the BART analysis, technology alternatives were investigated, and potential 

reductions in NOx, SO2, and PM10 emissions were evaluated. The following technology 

alternatives were investigated as improvements to reduce emissions and are listed below by 

pollutant: 

NOx emission controls: 

• Maintain current operation and utilize existing LNB with OFA 

• Optimize existing LNB with OFA through the utilization of a boiler consultant 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-2 

• Replace OFA with Rotating opposed fire air (ROFA) 

• Replace OFA with ROFA and Rotomix 

• Add selective non-catalytic reduction (SNCR) system to existing low NOx burners 

with OFA 

• Add selective catalytic reduction (SCR) system to existing low NOx burners with OFA 

SO2 emission controls: 

• Maintain current operation and utilize existing sodium bicarbonate injection system 

• Increase sodium bicarbonate injection rate to improve SO2 removal utilizing the existing 

sorbent injection system 

• Install lime spray dryer FGD system 

• Install wet limestone FGD system 

PM10 emission controls: Since fabric filter technology is considered to be BART, no 

alternative PM10 technologies were considered. 

BART Engineering Analysis 

The specific steps in a BART engineering analysis are identified in the Code of Federal 

Regulations (CFR) at 40 CFR 51 Appendix Y, Section IV. The evaluation must include the 

following: 

1. The identification of available, technically feasible, retrofit control options 

2. Consideration of any pollution control equipment in use at the source (which affects the 

availability of options and their impacts) 

3. The costs of compliance with the control options 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of compliance 

6. The degree of visibility improvement which may reasonably be anticipated from the use 

of BART 

These steps are incorporated into the BART analysis as follows: 

Step 1 – Identify All Available Retrofit Control Technologies 

• This engineering analysis evaluates control options and discusses control technologies 

for Healy Unit 1. 

Step 2 – Eliminate Technically Infeasible Options 

• The identification of available, technically feasible, retrofit control options 

• Available space was not a consideration in determining feasibility 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-3 

• Consideration of any pollution control equipment in use at the source (which affects the 

applicability of options and their impacts) 

Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Step 4 – Evaluate Impacts and Document the Results 

• The costs of compliance with the control options 

• The remaining useful life of the facility 

• The energy and non-air quality environmental impacts of compliance 

Step 5 – Evaluate Visibility Impacts 

• The degree of visibility improvement which may reasonably be anticipated from the use 

of BART 

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs 

included in the BART analyses are in 2008 dollars, and costs have not been escalated to the 

assumed 2014 BART implementation date. 

Coal Characteristics 

The only source of coal burned at Healy Unit 1 is low-sulfur sub-bituminous coal from the 

Usibelli Mine (UCM). 

BART Modeling Analysis 

The CALPUFF Gaussian puff dispersion modeling system to assess the visibility impacts of 

emissions from Healy 1 and Auxiliary Boiler # 1 on DNPP, which is a Class I area. Twenty 

four hour average actual emissions rate from the highest emitting day in the one year period 

from May 1, 2007 to April 30, 2008 were compared to current anticipated emission rates 

and those of evaluated control technologies. DNPP is located approximately 8 kilometers 

(5 miles) from the Healy Power Plant. 

Visibility improvements for all of the emission control technologies listed above were 

analyzed, and the results were compared utilizing a Least-Cost Envelope, as outlined in the 

draft EPA 1990 New Source Review Workshop Manual and referenced in the EPA BART 

guidelines. 

Least-Cost Envelope Analysis 

EPA typically uses the Least-Cost Envelope Analysis Methodology as an accepted 

methodology for selecting the most reasonable, cost-effective controls. Incremental costeffectiveness comparisons focus on annualized cost and emission reduction differences 

between dominant alternatives. The dominant set of control alternatives is determined by 

generating what is called the envelope of least-cost alternatives. This is a graphical plot of 

total annualized costs for a total emissions reductions for all control alternatives identified 

in the BART analysis. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-4 

To evaluate the impacts of the modeled control options on DNPP, the total annualized cost, 

cost per dV reduction, and cost per reduction in number of days above 0.5 dV were 

analyzed. This report provides a comparison of the average incremental costs between 

relevant control options for Healy 1; the total annualized cost versus number of days above 

0.5 dV, and the total annualized cost versus delta-deciview (∆dV) reduction. 

Just-Noticeable Differences in Atmospheric Haze 

Studies have been conducted that demonstrate only dV differences of approximately 1.5 to 

2.0 dV or more are perceptible by the human eye. Deciview changes of less than 1.5 cannot 

be distinguished by the average person. Therefore, the modeling analysis results indicate 

that based on the above, no observable visibility improvements at DNPP would be expected 

under any of the control options. 

BART Technologies 

The following summarizes the BART analysis for the Healy Power Plant 

NOx Emission Control 

Although Healy 1 has visibility impacts that exceed the 0.5 dV threshold defined in the 

BART rules as requiring evaluation of controls, this analysis shows applicable NOx BART 

controls to have no observable improvement to visibility. Therefore, the current plant 

controls for NOx are considered BART. 

Emissions and impacts from Auxiliary Boiler #1 are insignificant; therefore, no NOx control 

improvements are recommended for this unit. 

SO2 Emission Control 

Although Healy 1 has visibility impacts that exceed the 0.5 dV threshold defined in the 

BART rules as requiring evaluation of controls, this analysis shows applicable SO2 BART 

controls to have no observable improvement to visibility. Therefore, the current plant 

controls for SO2 are considered BART. 

Emissions and impacts from Auxiliary Boiler #1 are insignificant, and no SO2 controls are 

concluded as BART for this unit. 

PM10 Emission Control 

The existing fabric filter is concluded to be BART for Healy 1 since it is the best technology 

available for PM10 control. 

Emissions and impacts from Auxiliary Boiler #1 are insignificant, and no PM10 controls are 

concluded as BART for this unit. 

Recommendations 

It is recommended that the existing controls for all pollutants constitute BART. While 

technologies presented in this report have been shown to reduce emissions of visibility 

impairing pollutants, it is recommended that the no additional control technologies be 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ES-5 

implemented. From previous visibility studies that have been completed, it was concluded 

that visibility impairment at DNPP from Healy has not been observed by trained NPS 

observers. Also, there is little visibility benefit projected with expected emission 

improvement from the evaluated BART technologies. In addition, there may be unintended 

consequences of implementing the BART controls. Optimizing the existing low NOx burners 

(LNB) with over-fire air (LNB w/OFA) will result in an increase of CO emissions. Increasing 

the sodium bicarbonate injection rate has been shown in preliminary testing to increase 

emission of mercury. Consequently the undetectable slight potential decrease in visibility 

impairment does not warrant the increase in other pollutants. 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC ii 

Contents 

Section Page 

Executive Summary......................................................................................................................ES-1

Background ....................................................................................................................... ES-1

BART Engineering Analysis ........................................................................................... ES-2

Coal Characteristics.......................................................................................................... ES-3

BART Modeling Analysis................................................................................................ ES-3

Least-Cost Envelope Analysis ........................................................................................ ES-3

Just-Noticeable Differences in Atmospheric Haze ...................................................... ES-4

BART Technologies.......................................................................................................... ES-4

NOx Emission Control........................................................................................ ES-4

SO2 Emission Control.......................................................................................... ES-4

PM10 Emission Control ....................................................................................... ES-4

Recommendations............................................................................................................ ES-4

1.0 Introduction.........................................................................................................................1-1

2.0 Present Unit Operation......................................................................................................2-1

3.0 BART Engineering Analysis ............................................................................................3-1

3.1....Applicability...............................................................................................................3-1

3.2....BART Process .............................................................................................................3-1

3.2.1 BART NOx Analysis ..................................................................................3-2

3.2.2 BART SO2 Analysis .................................................................................3-10

3.2.3 BART PM10 Analysis ...............................................................................3-15

4.0 BART Modeling Analysis.................................................................................................4-1

4.1....Model Selection..........................................................................................................4-1

4.2....CALMET Methodology ............................................................................................4-1

4.2.1 Dimensions of the Modeling Domain ....................................................4-1

4.3....CALPUFF Modeling Approach...............................................................................4-4

4.3.1 Background Ozone and Ammonia .........................................................4-4

4.3.2 Stack Parameters........................................................................................4-4

4.3.3 Emission Rates ...........................................................................................4-5

4.3.4 Individual Control Scenarios...................................................................4-5

4.3.5 Modeling Process ......................................................................................4-9

4.3.6 Receptor Grids ...........................................................................................4-9

4.4....CALPOST....................................................................................................................4-9

4.5....Presentation of Modeling Results..........................................................................4-10

4.5.1 Degree of Visibility Change for Baseline vs. Preferred Scenario......4-10

5.0 Preliminary Assessment and Recommendations.........................................................5-1

5.1....Least-Cost Envelope Analysis..................................................................................5-1

5.1.1 Analysis Methodology..............................................................................5-2

5.1.2 Analysis of Results ....................................................................................5-9

5.2....BART Conclusions.....................................................................................................5-9

5.2.1 NOx Emission Control ..............................................................................5-9

5.2.2 SO2 Emission Control................................................................................5-9
CONTENTS (CONTINUED) 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC iii 

5.2.3 PM10 Emission Control .............................................................................5-9

5.2.4 Auxiliary Boiler # 1 ...................................................................................5-9

5.3....Just-Noticeable Difference in Atmospheric Haze .................................................5-9

5.4....Recommendations ...................................................................................................5-10

6.0 References............................................................................................................................6-1

Tables 

Table 2-1 Present Unit Operation .............................................................................................2-1 

Table 3-1 NOx Control Technology Emission Rates..............................................................3-4 

Table 3-2 NOx Control Cost Comparison ...............................................................................3-8 

Table 3-3 Summary of SO2 Control Effectiveness................................................................3-12 

Table 3-4 SO2 Control Cost .....................................................................................................3-14 

Table 4-1 User-Specified CALMET Options ...........................................................................4-3 

Table 4-2 CALMET Surface Stations........................................................................................4-4 

Table 4-3 BART Model Input Data...........................................................................................4-6 

Table 4-4 Stack Parameters and Emission Rates Healy Unit1..............................................4-7 

Table 4-5 Stack Parameters and Emission Rates Auxiliary Boiler #1..................................4-8 

TAble 4-6 Average Natural Levels of Aerosol Components ...............................................4-10 

Table 4-7 Costs and Visibility Modeling Results for Baseline vs. Individual 

 Control Scenarios.....................................................................................................4-11 

Table 4-8 Visibility Results for Auxiliary Boiler #1 .............................................................4-11 

Table 5-1 Class I Area Summary of Control Performance ....................................................5-2 

Table 5-2 Class I Area Incremental Data .................................................................................5-4 

Table 5-3 Annual Cost and Tons Removed Based on Current Operating Values.............5-7 

Figures 

Figure 3-1 First Year Control Cost for NOx Air Pollution Control Options ........................3-9 

Figure 3-2 First Year Control Cost for SO2 Air Pollution Control Options .......................3-15 

Figure 4-1 Healy BART Modeling Domain ..............................................................................4-2 

Figure 5-1 Least Cost Envelope Compared to Baseline ..........................................................5-5 

Figure 5-2 Least Cost Envelope Compared to Baseline ..........................................................5-5 

Figure 5-3 Least Cost Envelope Compared to Baseline ..........................................................5-6 

Figure 5-4 Least Cost Envelope Compared to Baseline ..........................................................5-6 

Figure 5-5 Additional Annual cost versus Additional Tons Removed Compared to 

 Existing Operations ...................................................................................................5-8 

Figure 5-6 Additional Annual cost versus Additional Tons Removed Compared to 

 Existing Operations ...................................................................................................5-8 

Appendix 

A Economic Analysis 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC iv 

Acronyms and Abbreviations 

ADEC Alaska Department of Conservation 

∆dV delta deciview, change in deciview 

°F degree Fahrenheit 

ADEC Alaska Department of Environmental Conservation 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

BTU British Thermal Unit 

CALMET Meteorological data preprocessing program for CALPUFF 

CALPOST Post-processing program for calculating visibility impacts 

CALPUFF Gaussian puff dispersion model 

CEM Continuous Emissions Monitor 

CFR Code of Federal Regulations

DNPP Denali National Park and Preserve 

dV deciview 

EPA United States Environmental Protection Agency 

FGD flue gas desulfurization 

GVEA Golden Valley Electric Association, Inc. 

HCCP Healy Clean Coal Project 

Healy 1 Healy Power Plant Unit 1 

hp horsepower 

km kilometer 

kW kilowatt 

kWh kilowatt-hour 

LAER lowest achievable emission rate 

lb pound 

LNB Low-NOx burner 

LOI loss on ignition 

MM5 Mesoscale Meteorological Model, Version 5 

MMBtu Million British thermal units 

MW megawatts 
ACRONYMS (CONTINUED) 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC v 

N2 nitrogen 

NO nitric oxide 

NOx nitrogen oxides 

NPS National Park Service 

OFA over fire air 

PM10 particulate matter less than 10 microns in aerodynamic diameter 

PSD prevention of significant deterioration 

RMC Regional Modeling Center 

ROFA Rotating Opposed Fire Air 

SCR selective catalytic reduction system 

SIP State Implementation Plan 

SNCR selective non-catalytic reduction system 

SO2 sulfur dioxide 

UCM Usibelli Coal Mine 

WRAP Western Regional Air Partnership 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 1-1 

1.0 Introduction 

Best Available Retrofit Technology (BART) guidelines (40 Code of Federal Regulations 

[CFR] Part 51) were established as a result of United States Environmental Protection 

Agency (EPA) regulations intended to reduce the occurrence of regional haze in national 

parks and other Class I protected air quality areas in the United States. These guidelines 

provide guidance for states when determining which facilities must install additional 

controls, and the type of controls that must be used. Facilities subject to BART controls were 

built between 1962 and 1977 and have the potential to emit more than 250 tons/year of 

visibility-impairing pollutants. 

The Alaska Department of Environmental Conservation (ADEC) has identified 

those eligible in-state facilities that are required to evaluate emissions under BART. 

The list includes the Golden Valley Electric Association, Inc. (GVEA) Power Plant 

Unit 1 (Healy 1) and Auxiliary Boiler #1. As a BART subject source, GVEA was required 

to submit a BART analysis, for the Healy Power Plant to ADEC by July 28, 2008. 

GVEA has addressed visibility impacts previously and has significant data worthy of 

consideration. GVEA received a Prevention of Significant Deterioration (PSD) construction 

permit and Permit to Operate No. 9431-AA001 from the ADEC in 1994 for operations at the 

Healy power plant when those operations were expanded to include the Healy Clean Coal 

Project (HCCP), a 50-megawatt (MW) coal-fired unit. Condition 26 of that Permit to Operate 

required GVEA to develop a Visibility Monitoring Plan and operate visibility monitoring 

equipment for the period prior to the initial startup of the HCCP through the completion of 

1 full year of commercial operation of HCCP. The Visibility Monitoring Plan was public 

noticed and submitted to EPA, ADEC and the NPS for approval. The objectives of the HCCP 

post-construction Visibility Monitoring Program were to collect sufficient visual and 

measurement data to: 

1. Provide reasonable assurance that nitrogen oxides (NOx), sulfur dioxide (SO2), and 

particle emissions from the HCCP and Healy Unit 1 sources (“Healy Power Plant”) were 

not adversely impairing visibility within the Class I area of DNPP, and 

2. Evaluate any trained National Park Service (NPS) observer’s reports of visibility 

impairment for their potential attribution to NOx, SO2, and particle emissions from 

operations of HCCP and Unit 1 . 

To meet the objectives of the Visibility Monitoring Program, photographic and /or air 

quality instrumentation was established at three monitoring stations. One station was 

established on a hill overlooking the plant to capture plant operations (Garner Hill); one was 

set up at the DNPP visitors center, and an ambient air monitoring station was set up at the 

Park Boundary between the two camera sites (Bison Gulch Monitoring Station)Photographic 

monitoring equipment recorded visibility and weather conditions using: 

• Continuous time-lapse video from Garner Hill of the Healy Power Plant 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 1-2 

• Continuous time-lapse video of the Nenana Valley north of the DNPP Visitor Access 

Center 

A comparison of the time variation of the SO2 concentrations, as determined by ambient 

SO2 monitoring, and light scattering by sulfate particles determined source attribution of the 

sulfate. These data were used to estimate the contribution of the SO2 emissions from the 

Healy Power Plant (Healy 1 and HCCP) to light scattering by particles within DNPP. 

Monitoring equipment at the Bison Gulch Monitoring Station continuously measured, with 

5-minute resolution: 

• Light scattering by fine particles using a heated, gas-tight integrating nephelometer with 

a 2.5-μm cutpoint cyclone 

• Ambient air SO2 concentrations 

• Relative humidity 

• Ambient temperature 

• Wind speed and wind direction 

This Visibility Monitoring Program was initiated when HCCP began its first year of the 

demonstration period, which was scheduled for January 1, 1998. Therefore, the monitoring 

program began immediately prior to that date (late December 1997). During the time period 

the visibility monitoring program was active, Healy 1 was operating with the current NOx

control configuration, the current bag house, but the current SO2 reduction system was not 

operating. Therefore, the visibility monitoring program was active at a time when both units 

were operating and Healy 1 was emitting more SO2 than it does now. Additionally, HCCP 

had not been fully optimized resulting in emissions above normal operating conditions. 

The duration of the post-construction monitoring program was for an agreed upon 2 years 

(1 year of demonstration operation and 1 year of commercial operation). The monitoring 

program ended during in 2000. Quarterly reports were submitted to ADEC, EPA and the 

NPS. In 2000, the ADEC, EPA and NPS all agreed the Visibility Monitoring Program could 

be temporarily shut down as HCCP never reached full commercial operation. HCCP has not 

operated since.During the 2-year time period no visibility impairment was observed by 

trained NPS observers while Healy 1 was operating at full load. This data demonstrate that 

actual visibility impairment at DNPP from Healy has not been detectable, even with both 

units operating. During the visibility monitoring program, there were occasions when a 

slight plume was visible and recorded by video.. However, no correlation was reached 

between this slight plume and any visibility issues within DNPP. 

At the same time, a three year study in which particles that cause or contribute to regional 

haze were measured and analyzed to determine if Healy was contributing to regional haze. 

The study was funded by GVEA, managed by the NPS, and conducted by Air Resource 

Specialists, Inc. and the University of Alaska –Fairbanks. Results of t his study are 

summarized in a report entitled “Final Report on the Results from the Poker Flat, Denali 

National Park and Preserve, and Trapper Creek CASTNET Protocol Sites, July 1998 through 

June 2001 and was submitted to the agencies. The report concluded that there was no 

specific indication that operations form Healy Power Plant contributed to regional haze.As 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 1-3 

defined in the BART guidelines, there are five basic elements that are considered when 

evaluating BART. These are defined as: 

1. The cost of the controls 

2. The energy and non-air environmental impacts of compliance 

3. Any existing pollution control technology in use at the source 

4. The remaining useful life of the source 

5. The degree of improvement in visibility which may reasonably be anticipated from the 

use of such technology 

This report documents the BART analysis that was performed on Healy 1 and Auxiliary 

Boiler #1 by CH2M HILL for GVEA. The analysis was performed for the pollutants: NOx, 

SO2, and particulate matter less than 10 microns in aerodynamic diameter (PM10), because 

they are the primary criteria pollutants that affect visibility. 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 2-1 

2.0 Present Unit Operation 

Healy 1 is a nominal 25-MW unit located in Healy, Alaska, approximately 8 kilometers 

(5 miles) from DNPP. The unit is a wall-fired, dry-bottom boiler manufactured by Foster 

Wheeler. The BART presumptive NOx limit for dry-bottom wall-fired boilers burning subbituminous coal is 0.23 lb/MMBtu. 

Low NOx burners (LNB) and over-fired air (OFA) ports were installed in 1996. Particulate 

emissions are collected by a reverse gas baghouse installed in the early 1970s. Sulfur oxides 

are controlled by a dry sorbent injection system installed in 1999. At the present time 

sodium bicarbonate is the sorbent which is injected into the flue gas after the air heater. 

Auxiliary Boiler #1 is only used to supply heat to the Healy 1 building during shutdown 

periods or during emergency repairs to Healy 1. Auxiliary Boiler #1 also provides steam for 

water processing and hot potable water to the HCCP if called for during periods when 

Healy 1 is not operating. The unit is also fired monthly for maintenance checks. 

Healy 1 began operation in 1967. This analysis is based on the unit operating with a 

remaining useful life of 15 years. This report does not attempt to quantify any additional life 

extension costs needed to allow the unit and these control devices to operate beyond 

15 years. 

Table 2-1 lists additional unit information and study assumptions for this analysis. Coal 

characteristics are included in the table. The only source of coal burned at Healy 1 is the 

Usibelli Coal Mine (UCM). The coal from this mine is ranked as low-sulfur sub-bituminous. 

TABLE 2-1 

Present Unit Operation 

Healy 1 

General Plant Data 

Site Elevation Feet Above Mean Sea Level 1,260 

Stack Height Feet 122 

Stack Exit Internal Diameter Feet /Exit Area Sq. Ft. 4.83/18.31 

Stack Exit Temperature °F 320 

Stack Exit Velocity Ft/Sec 136.51 

Stack Flow Actual Cubic Feet per Minute (acfm) 150,000 

Annual Unit Capacity Factor (%) 96 to 100 

Net Unit Output (MW) 25.5/26.0 (Winter/Summer range) 

Net Unit Heat Rate (Btu/kilowatt hour [kWh])(100% load) 13,500 

Boiler Heat Input (MMBtu/Hr)(100% load) 340 

Type of Boiler Wall-fired, dry bottom 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 2-2 

TABLE 2-1 

Present Unit Operation 

Healy 1 

Boiler Fuel Coal with oil start-up 

Coal Source1 UCM 

Coal Heating Value (Btu/lb) 6766 

Coal Sulfur Content (wt. %) 0.17 

Coal Ash Content (wt. %) 13.65 

Coal Moisture Content (wt. %) 28.97 

Coal Nitrogen Content (wt. %) 0.57 

Current NOx Controls Low-NOx Burners and OFA 

Current SO2 Controls Dry sorbent injection (sodium bicarbonate) 

Current PM10 Controls Reverse-gas fabric filter 

1 Coal information represents one sample from the UCM dated 2-07-07 and represents typical but not 

average coal burned at Healy. 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-1 

3.0 BART Engineering Analysis 

3.1 Applicability 

In compliance with regional haze requirements, the State of Alaska must prepare and 

submit visibility State Implementation Plans (SIPs) to the EPA for Class I areas. The State 

has estimated that the formal submittal of the SIPs will occur by 2009. The first phase of the 

regional haze program is the implementation of BART emission controls on all BART 

eligible units, within 5 years after EPA approval of the SIP. This BART analysis evaluates 

retrofit control options and discusses BART controls for Healy 1. 

3.2 BART Process 

The specific steps in a BART engineering analysis are identified in 40 CFR 51 Appendix Y, 

Section IV. The evaluation must include the following: 

1. The identification of available, technically feasible, retrofit control options 

2. Consideration of any pollution control equipment in use at the source (which affects the 

availability of options and their impacts) 

3. The costs of compliance with the control options 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of compliance 

6. The degree of visibility improvement which may reasonably be anticipated from the use 

of BART 

These steps are incorporated into the BART analysis as follows: 

Step 1 – Identify All Available Retrofit Control Technologies 

• This engineering analysis evaluates control options, including existing controls and 

discusses control technologies for Healy 1. 

Step 2 – Eliminate Technically Infeasible Options 

The identification of available, technically feasible, retrofit control options 

• Space was not a consideration in determining feasibility 

• Consideration of any pollution control equipment in use at the source (which affects the 

applicability of options and their impacts) 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-2 

Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Step 4 – Evaluate Impacts and Document the Results 

• The costs of compliance with the control options 

• The remaining useful life of the facility 

• The energy and non-air quality environmental impacts of compliance 

Step 5 – Evaluate Visibility Impacts 

• The degree of visibility improvement which may reasonably be anticipated from the use 

of BART 

Consideration was made of applicable emissions control equipment, the costs of compliance 

associated with the control options, and the energy and non-air quality environmental 

impacts of compliance using identified control technologies. In some cases, enhancing the 

performance of the existing control equipment was considered. 

All costs included in the BART analysis are in 2008 dollars (not escalated to 2014 BART 

implementation date). 

3.2.1 BART NOx Analysis 

The 1994 PSD permit that allowed construction of HCCP resulted in extensive discussions 

between GVEA and ADEC on the operations of Healy 1 with regard to NOx and CO 

emissions. ADEC requested that GVEA operate Healy 1 with the goal of minimizing NOx

and CO emissions. The plant has been operated with this dual goal ever since. The BART 

process is focused on reducing NOx, SO2, and PM10 emissions but not CO. Therefore, any 

consideration of reducing NOx must accommodate the earlier direction from ADEC where 

an increase in CO is an undesirable impact. 

NOx formation in coal-fired boilers is a complex process that is dependent on a number of 

variables, including operating conditions, equipment design, and coal characteristics. 

3.2.1.1 Formation of NOx

During coal combustion, NOx is formed in three different ways. The dominant source of 

NOx formation is the oxidation of fuel-bound nitrogen (fuel NOx). During combustion, part 

of the fuel-bound nitrogen is released from the coal with the volatile matter, and part is 

retained in the solid portion (char). The nitrogen chemically bound in the coal is partially 

oxidized to nitrogen oxides (nitric oxide [NO] and nitrogen dioxide [NO2]) and partially 

reduced to molecular nitrogen (N2). A smaller part of NOx formation is due to high 

temperature fixation of atmospheric nitrogen in the combustion air. A very small amount of 

NOx is called “prompt” NOx. Prompt NOx results from an interaction of hydrocarbon 

radicals, nitrogen, and oxygen. 

In a conventional pulverized coal burner, air is introduced with turbulence to promote good 

mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in 

the air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form 

NOx. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-3 

Coal characteristics directly and significantly affect NOx emissions from coal combustion. 

Coal ranking is a means of classifying coals according to their degree of metamorphism in 

the natural series, from lignite to sub-bituminous to bituminous and on to anthracite. Lower 

rank coals, such as the sub-bituminous coals from the UCM, produce lower NOx emissions 

than higher rank bituminous coals, due to their higher reactivity and lower nitrogen 

content. The fixed carbon to volatile matter ratio (fuel ratio), coal oxygen content, and rank 

are good relative indices of the reactivity of a coal. Lower rank coals release more 

organically bound nitrogen earlier in the combustion process than do higher rank 

bituminous coals. When used with low NOx burners, sub-bituminous coals create a longer 

time for the kinetics to promote more stable molecular nitrogen, and hence result in lower 

NOx emissions. 

Coal quality characteristics also impact the design and operation of the boiler and associated 

auxiliary equipment. Minor changes in quality can sometimes be accommodated through 

operational adjustments or changes to equipment. It is important to note, however, that 

consistent variations in quality or assumptions of “average” quality for performance 

projections can be problematic. This is particularly troublesome when dealing with 

performance issues that are very sensitive to both coal quality and combustion conditions, 

such as NOx formation. There are some additional considerations that illustrate the 

complexity of achieving and maintaining low NOx emissions with pulverized coal on a 

consistent shorter term, such as a 30-day rolling average basis. Coal from the UCM mine is 

classified as sub-bituminous, with low BTU content and high moisture and ash. Coal quality 

also can vary significantly, which may impact stable boiler operation. 

Good combustion is based on the “three Ts”: time, temperature, and turbulence. These 

parameters, along with a “design” coal are taken into consideration when designing a boiler 

and associated firing equipment such as fans, burners, and pulverizers. If a performance 

requirement such as NOx emission limits is subsequently changed, conflicts with and 

between other performance issues can result. 

The BART analysis for NOx emissions from Healy 1 is further described in this section. 

3.2.1.2 Step 1: Identify All Available Retrofit Control Technologies 

The first step of the BART process is to evaluate NOx control technologies with practical 

potential for application to Healy 1, including those control technologies identified as Best 

Available Control Technology (BACT) or lowest achievable emission rate (LAER) by 

permitting agencies across the United States. A broad range of information sources have 

been reviewed in an effort to identify potentially applicable emission control technologies. 

NOx from Healy 1 emissions are currently controlled through the use of LNB and OFA. 

The following potential NOx control technology options were considered: 

• Maintain current operation and utilize existing LNB with OFA 

• Optimize existing LNB with OFA through the utilization of a boiler consultant 

• Replace OFA with rotating opposed fire air (ROFA) 

• Replace OFA with ROFA and Rotomix 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-4 

• Add selective non-catalytic reduction (SNCR) system to existing low NOx burners with 

OFA 

• Add selective catalytic reduction (SCR) system to existing Low NOx burners with OFA 

3.2.1.3 Step 2: Eliminate Technically Infeasible Options 

For Healy 1, technical feasibility was primarily determined by physical constraints, the 

current boiler configuration and size, and impact on boiler operation and efficiency. 

Healy 1 has a current NOx emission rate of 0.25 pound per million British thermal units 

(lb/MMBtu), which is slightly above the presumptive BART level of 0.23 lb/MMBtu. 

For this BART analysis, information pertaining to SNCR and SCR was based on 

CH2M HILL’s project information, and the cost estimate for SNCR was updated by Fuel 

Tech in July 2008. GVEA provided additional emissions data and cost estimate for boiler 

tuning. Also, CH2M HILL solicited a budgetary estimate from Mobotec for their ROFA 

Rotamix technologies. 

Table 3-1 summarizes the control technology options evaluated in this BART analysis, along 

with projected NOx emission rates. 

TABLE 3-1 

NOx Control Technology Emission Rates 

Healy 1 

Technology Projected Emission Rate (lb/MMBtu) 

Maintain Current Operation 0.25a

Optimize Existing LNB w/OFA 0.23b

Replace OFA with ROFA 0.15 

ROFA and Rotamix 0.11 

LNB w/OFA & SNCR 0.19 

LNB w/OFA & SCR 0.07 

a

 – Based on emissions from a typical operating day in 2008, and represents a realistic level estimate of future 

emissions when operating existing equipment. 

b

 – Presumptive limit for > 200 MW wall fired boilers burning sub-bituminous coal 

3.2.1.4 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Preliminary vendor proposals, such as those used to support portions of this BART analysis, 

may be technically feasible and provide expected emission rates; however, they include 

inherent uncertainties. These proposals are usually prepared in a limited time frame, may be 

based on incomplete information, may contain over-optimistic conclusions, and are nonbinding. Therefore, emission rate values obtained in such preliminary proposals must be 

qualified, and it must be recognized that contractual guarantees are established only after 

more detailed analysis has been completed. The following subsections describe the control 

technologies and the control effectiveness evaluated in this BART analysis. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-5 

Maintain Current Operation. This option would maintain the current operation of LNB and 

OFA. Expected future NOx emissions are estimated at 0.25 lb/MMBtu, and were derived 

from typical past actual emission rates in 2008. 

Utilizing committed or currently installed technology is consistent with BART analysis 

approaches CH2M HILL has used in previous BART analyses. For those cases when 

committed or existing technology and corresponding emission rates are consistent with 

other BART control options, evaluation of currently installed emissions control equipment is 

warranted. 

Optimizing Existing LNB/OFA System. The mechanism used to lower NOx with low NOx 

burners is to stage the combustion process and provide a fuel-rich condition initially; this is 

so oxygen needed for combustion is not diverted to combine with nitrogen and form NOx. 

Fuel-rich conditions favor the conversion of fuel nitrogen to N2 instead of NOx. Additional 

air (or OFA) is then introduced downstream in a lower temperature zone to burn out the 

char. 

Healy 1 currently has an LNB/OFA system which was installed in 1996 to facilitate 

construction of HCCP. This system has been operating for an extended period of time, and 

plant personnel have exerted considerable effort to optimize performance (minimize CO 

within the existing permit NOx limits); it has not been optimized with the goal of 

minimizing NOx emissions. 

Optimization of the LNB/OFA system could be attempted by utilizing a boiler consultant 

with the intent of reaching a guideline (presumptive limit for 200MW unit) NOx target 

emissions of 0.23 lb/MMBtu. While this may or may not be achievable, NOx emissions 

minimization will likely also impact other boiler operating parameters such as loss on 

ignition (LOI), carbon monoxide (CO), and excess air. Therefore, the impact on all emissions 

must be considered when attempting to reduce NOx. 

ROFA. Mobotec markets ROFA as an improved second generation OFA system. Mobotec 

states that the flue gas volume of the furnace is set in rotation by asymmetrically placed air 

nozzles. Rotation is reported to prevent laminar flow, so that the entire volume of the 

furnace can be used more effectively for the combustion process. In addition, the swirling 

action reduces the maximum temperature of the flames and increases heat absorption. The 

combustion air is also mixed more effectively. A typical ROFA installation would have a 

booster fan(s) to supply the high-velocity air to the ROFA boxes, and Mobotec would 

propose one 200 horsepower (hp) fan for Healy 1. 

Mobotec expects to achieve a NOx emission rate of 0.15 lb/MMBtu using ROFA technology. 

Results of computational fluid dynamics modeling will determine the quantity and location 

of new ROFA ports, as well as the determining the need for modification or replacement of 

the existing burners. 

ROFA with Rotomix. The Rotamix system has been developed to optimize the reduction of 

unwanted substances, such as NOx. To optimize NOx reduction, an amine-based reagent 

such as ammonia is added. The ammonia is added using lances that are inserted in the 

ROFA/Rotomix nozzles. The high-velocity air in the ROFA system carries the chemicals 

into the center of the furnace. Mobotec markets ROFA as an improved second generation 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-6 

OFA system. Mobotec expects to achieve a NOx emission rate of 0.11 lb/MMBtu using 

ROFA/ Rotomix technology. 

SNCR. Selective non-catalytic reduction is generally utilized to achieve modest NOx 

reductions on smaller units. With SNCR, an amine-based reagent such as ammonia – or 

more commonly urea – is injected into the furnace within a temperature range of 

1,600 degrees Fahrenheit (°F) to 2,100°F, where it reduces NOx to nitrogen and water. 

NOx reductions of up to 60 percent have been achieved, although 20 to 40 percent is more 

realistic for most applications. 

Reagent utilization, which is a measure of the efficiency with which the reagent reduces 

NOx, can range from 20 to 60 percent, depending on the amount of reduction, unit size, 

operating conditions, and allowable ammonia slip. With low reagent utilization, low 

temperatures, or inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to 

create problems downstream. The ammonia may render fly ash unsaleable, react with sulfur 

to foul heat exchange surfaces, and/or create a visible stack plume. Reagent utilization can 

have a significant impact on economics, with higher levels of NOx reduction generally 

resulting in lower reagent utilization and higher operating cost. 

At Healy 1, a reduction of 25 percent in current NOx emissions for the addition of SNCR 

results in a projected emission rate of 0.19 lb/MMBtu for SNCR. 

SCR. SCR works on the same principle as SNCR, but a catalyst is used to promote the 

reaction. Ammonia is injected into the flue-gas stream, where it reduces NOx to nitrogen 

and water. Unlike the high temperatures required for SNCR, the reaction takes place on the 

surface of a vanadium/titanium-based catalyst at a temperature range between 580°F to 

750°F. Due to the catalyst, the SCR process is more efficient than SNCR. The most common 

type of SCR is the high-dust configuration, where the catalyst is located upstream of the 

airheater and downstream from the economizer. 

The design basis for Healy 1 results in a projected NOx emission rate of 0.07 lb/MMBtu. 

All of the control technologies described above are feasible for Healy 1, with the exception 

of consideration of potential space limitations. 

Level of Confidence for Vendor Post-Control Emissions Estimates. In order to determine the 

level of NOx emissions needed to achieve compliance consistently with an established goal, 

NOx emissions from coal-fired generating units have been previously reviewed. As a result 

of this review, it was noted that NOx emissions can vary significantly around an average 

emissions level. Variations may result for many reasons, including coal characteristics, unit 

load, boiler operation including excess air, boiler slagging, burner equipment condition, coal 

mill fineness, and so forth. 

Recommended steps utilized for determining a level of confidence for the vendor expected 

values are as follows: 

1. Establish expected NOx emissions value from vendor. 

2. Evaluate vendor experience and historical basis for meeting expected values. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-7 

3. Review and evaluate unit physical and operational characteristics and restrictions. The 

fewer variations there are in operations, coal supply, etc., the more predictable and less 

variant the NOx emissions are. 

4. For each technology expected value, there is a corresponding potential for actual NOx

emissions to vary from this expected value. From the vendor information presented, 

along with anticipated unit operational data, an adjustment to the expected value can be 

made. 

Therefore, vendor emission estimates should not be considered as absolute values for 

purposes of establishing permit limits for Healy 1. 

3.2.1.5 Step 4: Evaluate Impacts and Document the Results 

This step involves the consideration of energy, environmental, and economic impacts 

associated with each control technology. The remaining useful life of the plant is also 

considered during the evaluation. 

Energy Impacts. Optimization of the existing LNB with OFA is not expected to impact the 

boiler efficiency or draft fan power usage significantly. Therefore, this modification should 

not have significant energy impacts. 

The Mobotec ROFA and ROFA/Rotomix systems require installation and operation of one 

200 hp ROFA fan. 

An SCR retrofit impacts the existing flue gas fan system, which can typically result in 

additional pressure drop of 6 to 8 inches H2O. There would also be additional pumping 

costs associated with both SCR and SNCR injection systems. 

Environmental Impacts. Tuning of the LNB with OFA will likely also affect the level of 

unburned carbon in the ash (commonly referred to as LOI) and CO emissions. A Mobotec 

ROFA installation may also affect LOI levels and CO emissions, which will impact 

combustion efficiency. In previous discussions with ADEC, GVEA has been requested to 

minimize CO emissions. When optimizing the current LNB and OFA system with a goal of 

minimizing NOx emissions, or with the installation of a Mobotec ROFA system, there will 

be emissions trade-offs between NOx, CO, LOI, as well as potential impacts to boiler 

efficiency. Rotamix, SNCR, and SCR installations will result in some level of ammonia 

emissions. Rotamix, SNCR, and SCR installations could also impact the salability and 

disposal of fly ash due to ammonia levels and could potentially create a visible stack plume, 

which may negate other visibility improvements. Other environmental impacts involve the 

storage of ammonia (especially if anhydrous ammonia is used) and the transportation of the 

ammonia to the power plant site. 

Economic Impacts. Costs and schedules for SCR were developed using CH2M HILL’s 

internal proprietary database, and supplemented (as needed) by vendor-obtained price 

estimates. Budgetary cost information for SNCR was furnished to CH2M HILL by Fuel 

Tech, and costs for the ROFA and ROFA/Rotomix systems were obtained from Mobotec. 

A comparison of the technologies on the basis of costs, design control efficiencies, and 

tons of NOx removed is summarized in Table 3-2, and the first year control costs in 

Figure 3-1. The complete Economic Analysis is contained in Appendix A. 
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

TABLE 3-2 NOx Control Cost Comparison 

Healy 1 

Factor 

Current 

Operation with 

Existing LNB 

w/OFA 

Optimizing 

Existing LNB 

w/OFA SNCR ROFA ROFA/Rotam

Major Materials Design Costs $0 $20,000.0 $1.1 Million $4.6 Million $6.9 Million Total Installed Capital Costs $0 $20,000.0 $2.5 Million $4.6 Million $6.9 Million Total First Year Fixed and Variable O&M Costs 

$0 - $0.1 Million $0.1 Million $0.3 Million 

Total First Year Annualized Cost 

$0 $2,336.6 $0.4 Million $0.7 Million $1.1 Million 

Power Consumption (MW) 0 - 0.02 0.15 0.26 Annual Power Usage (Million kW-Hr/Yr) 

0 - 0.2 1.3 2.3 

NOx Design Control Efficiencya N/A 8.0% 25.0% 40.0% 58.0% 

Tons NOx Removed per Year 0 30 92 148 214 

First Year Average Control Cost ($/Ton of NOx Removed) 

0 79 4,533 4,553 5,108 

Incremental Control Cost ($/Ton of NOx Removed) 

0 79 6,629 4,585 6,341 

Note: Current operation is shown as zero for comparison purposes only. 

a--Assuming current emissions as baseline 
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC FIGURE 3-1 First Year Control Cost for NOx Air Pollution Control Options 

Healy 1 

0

1,0002,0003,0004,0005,0006,0007,000

Maintain Current

Operation

Optimizing Existing

LNB w/OFA

SNCR ROFA ROFA/Rotamix 

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-10 

3.2.1.6 Step 5: Evaluate Visibility Impacts 

Please see Section 4.0, BART Modeling Analysis. 

3.2.2 BART SO2 Analysis 

SO2 forms in the boiler during the combustion process and is primarily dependent on coal 

sulfur content. The BART analysis for SO2 emissions on Healy 1 is described below. 

3.2.2.1 Step 1: Identify All Available Retrofit Control Technologies 

A broad range of information sources was reviewed in an effort to identify potentially 

applicable emission control technologies for SO2 at Healy 1; this included control 

technologies identified as BACT or LAER by permitting agencies across the United States. 

The following potential SO2 control technology options were considered: 

• Maintain current operation and utilize existing sodium bicarbonate injection system 

• Increase sodium bicarbonate injection rate to improve SO2 removal utilizing the existing 

sorbent injection system 

• Install lime spray dryer FGD system 

• Install wet limestone FGD system 

3.2.2.2 Step 2: Eliminate Technically Infeasible Options 

Maintain Current Operation. This option would maintain the current operation of the dry 

sorbent injection system. Expected future SO2 emissions are derived from typical past actual 

emission rates in 2008. 

Utilizing committed or currently installed technology is consistent with BART analysis 

approaches CH2M HILL has used in previous BART analyses. For those cases when 

committed or existing technology and corresponding emission rates are consistent with 

other BART control options, evaluation of currently installed emissions control equipment is 

warranted. 

Increase Sodium Bicarbonate Injection Rate. Healy 1 currently operates a dry sorbent 

injection system which injects sorbent into the flue gas after the air heater and upstream of 

the baghouse or fabric filter to control SO2 emissions. Since the system was installed in 

1999, GVEA has used three different materials as sorbent in an attempt to maximize the 

efficiency of the system. When the system was first installed, calcium carbonate was used as 

the sorbent. Several years later GVEA began experimenting with trona (a sodium 

sesquicarbonate) and was able to increase SO2 capture significantly. In 2007, GVEA was able 

to optimize the system even further by using sodium bicarbonate The SO2 in the flue gas 

reacts with the sodium bicarbonate to form dry particles, which are captured downstream in 

the existing fabric filter. Under current operation, the dry sodium bicarbonate system 

consistently achieves approximately 50 percent removal of SO2 (percent removals listed in 

the SO2 BART analysis section will be calculated from an uncontrolled emission levels 

unless specifically noted otherwise). An increase in the amount of sodium bicarbonate 

injected may have the potential to achieve SO2 removal of up to 70 percent. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-11 

However, there are several significant potential issues that must be addressed with 

increasing sodium bicarbonate injection with the existing dry sorbent injection system. All 

potential impacts must be considered when considering increasing the sodium bicarbonate 

injection rate: 

• The existing sorbent injection system design and equipment may not be able to support 

the required sodium bicarbonate feed rate to remove SO2 continuously at 70 percent 

removal. While it may be possible to achieve 70 percent removal on a short-term basis, it 

is not feasible to operate the existing equipment at that rate continuously with no 

interruptions. 

• From operational experience on other similar dry sodium injection systems, a brown 

NO2 plume may be visible at higher SO2 removal rates. It is uncertain whether a brown 

plume would be visible at a 70 percent removal rate. 

• From previous testing at Healy 1 in March 2008, higher sodium bicarbonate injection 

rates corresponded with higher mercury emissions. 

While it may be possible to operate the current SO2 FGD system up to a 70 percent removal 

capability for some periods of time, consistently achieving this removal rate is not feasible 

when taking into account equipment capacities, SO2 removal performance, and other 

environmental impacts. While a new dry sodium bicarbonate injection system may be 

designed and installed with adequate capacity, concerns with the brown plume and 

potential higher mercury emission issues would remain. Therefore, increasing the dry 

sodium bicarbonate injection rate may be able to improve the SO2 reduction from the 

current 50 percent removal to a maximum of 70 percent. 

While the current sodium bicarbonate feed rate is approximately 370 lb/hr, the required 

feed rate to achieve a continuous 70 percent reduction is uncertain. Although current 

information is limited regarding the required sodium bicarbonate injection rate required to 

achieve up to an overall 70 percent reduction, for purposes of this BART analysis, an 

estimated feed rate of 700 lb/hr up to 1400 lb/hr is estimated. This would result in an 

additional $0.5 to $1.0 million in additional annual sorbent cost, and an estimated 

$750,000 was assumed for economic evaluation purposes. Sorbent injection rates also vary 

according to coal sulfur levels. 

New Lime Spray Dryer FGD System. The lime spray dryer typically injects lime slurry in the 

top of the absorber vessel with a rapidly rotating atomizer wheel. The rapid speed of the 

atomizer wheel causes the lime slurry to separate into very fine droplets that intermix with 

the flue gas. The SO2 in the flue gas reacts with the calcium in the lime slurry to form dry 

calcium sulfate particles. At Healy 1, this dry particulate matter would be captured 

downstream in the existing baghouse, along with the fly ash. It is assumed that a lime spray 

dryer system will produce a dry waste product suitable for landfill disposal. 

The lime spray dryer FGD system with the existing baghouse is projected to achieve 

up to 75 percent SO2 removal at Healy 1. This would result in an estimated controlled 

SO2 emission rate of 0.15 lb/MMBtu, based on an uncontrolled SO2 emission rate of 

0.60 lb/MMBtu. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-12 

Operation of a lime spray dryer FGD system would result in a wet plume, reduced plume 

rise, and the potential for higher near field air quality impacts. 

New Wet Limestone FGD System. Wet limestone FGD systems operate by treating the flue 

gas in large scrubber vessels with a limestone solution. Wet FGD scrubbers use an absorber 

tower in which flue gas is contacted by the limestone slurry, resulting in conversion of 

SO2, in the flue gas into calcium sulfate (gypsum), with carbon dioxide (CO2) going up the 

stack. The calcium sulfate is removed from the scrubber and disposed, and it is assumed 

that the waste product from a wet limestone scrubber system is suitable for landfill disposal. 

Installation of a wet limestone FGD system at Healy 1 is estimated to achieve approximately 

88 percent SO2 removal which equates to an SO2 outlet emission rate of 0.07 lb/MMBtu. 

Operation of a wet limestone FGD system would result in a wet plume, reduced plume rise, 

and the potential for higher near field air quality impacts. 

All of the control technologies described above are feasible for Healy 1, with the exception 

of consideration of potential space limitations. 

3.2.2.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Healy 1 currently has an uncontrolled SO2 emission rate of approximately 0.60 lb/MMBtu 

and a controlled SO2 emission rate of 0.30 lb/MMBtu, which equates to a removal 

performance of approximately 50 percent. Table 3-3 presents the control technologies being 

evaluated and the expected removal efficiencies and emission rates. 

TABLE 3-3 

Summary of SO2 Control Effectiveness 

Healy 1 

Control Technology 

Removal Efficiency 

(Current Emission 

Baseline/Uncontrolled Emission 

Baseline) 

Projected Emission Rate 

(lb/MMBtu) 

Maintain Current operation NA/50% 0.30a

Increase sodium bicarbonate feed 

rate utilizing existing dry sorbent 

injection system 

Up to 40%/Up to 70% 0.18 

Lime spray dryer 50%/75% 0.15 

Wet limestone 77%/88% 0.07 

a -- Based on emissions from a typical operating day in 2008, and represents a realistic level estimate of future 

emissions when operating existing equipment 

3.2.2.4 Step 4: Evaluate Impacts and Document the Results 

This step involves the consideration of energy, environmental, and economic impacts 

associated with each control technology. The remaining useful life of the plant is also 

considered during the evaluation. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-13 

Energy Impacts. The installation of a new lime spray dryer or wet limestone FGD system 

would require approximately 240 kilowatts (kW) of additional power. Upgrading the 

existing dry sorbent injection system would require approximately 20 kW of additional 

power. 

Environmental Impacts. Based on recent stack testing, upgrading the existing dry sorbent 

sodium bicarbonate FGD system from 50 percent to up to 70 percent removal performance 

will result in an increase in mercury emissions and may result in a brown plume. 

Installation of a new lime spray dryer or wet limestone FGD system will result in the storage 

of new chemicals onsite and a new waste stream for the facility. The exit flue gas stack 

temperature with both of these technologies will be less than the current operation, thus flue 

gas buoyancy will be decreased (see Section 5). In addition, saturated flue gas would 

significantly increase the probability of creating fog during the summer and ice fog during 

the winter, in the area surrounding the plant. 

Economic Impacts. A summary of the costs and amount of SO2 removed for the control 

technologies discussed above is provided in Table 3-4, and a comparison of the first-year 

control cost ($/ton removed) is shown in Figure 3-2. The complete economic analysis is 

contained in Appendix A.
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-14 

TABLE 3-4 SO2 Control Cost 

Healy 1 

Factor 

Maintain Current 

Operation with Existing 

Dry Sorbent Injection 

Optimizing Existing 

Dry Sorbent Injection Dry FGD 

Major Materials Design Costs 0 $0.0 Million $3.6 Million Total Installed Capital Costs 0 $0.0 Million $8.4 Million Total First Year Fixed and Variable Operations and Maintenance Costs 

0 $0.8 Million $0.6 Million 

Total First Year Annualized Cost 0 $0.8 Million $1.5 Million Power Consumption (MW) 0 0.02 0.24 Annual Power Usage (kW-Hr/Yr) 0 0.2 2.1 SO2 Design Control Efficiencya N/A Up to 40.0% 50.0% 

Tons SO2 Removed per Year 0 177 222 

First Year Average Control Cost ($/Ton of SO2

Removed) 

0 4,275 4,255 

Incremental Control Cost ($/Ton of SO2 Removed) 0 4,275 17,516 

a--Assuming current emissions as baseline 
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC FIGURE 3-2 First Year Control Cost for SO2 Air Pollution Control Options 

Healy 1 

0

2,0004,0006,0008,000

10,00012,00014,00016,00018,00020,000

Maintain Current Operation Optimizing Existing Dry Sorbent

Injection

Dry FGD Wet Lim

Air Pollution Control Option

Control Cost ($/Ton SO2 Removed)

First Year Average Control Cost ($/Ton SO2 Rem.) First Year Incremental Cost
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 3-15

3.2.2.5 Step 5: Evaluate Visibility Impacts 

Please see Section 4.0, BART Modeling Analysis. 

3.2.3 BART PM10 Analysis 

Maintain Current Operation. This option would maintain the current operation of the 

baghouse. Expected future NOx emissions are estimated at 0.015 lb/MMBtu, which is 

consistent with expected emissions from a baghouse. It is assumed that the Healy 

Unit 1 baghouses is either achieving, or is capable of achieving, the 0.015 lb/MMBtu 

emission value. 

Utilizing committed or currently installed technology is consistent with BART analysis 

approaches CH2M HILL has used in previous BART analyses. For those cases when 

committed or existing technology and corresponding emission rates are consistent with 

other BART control options, evaluation of currently installed emissions control equipment is 

warranted. 

Healy 1 currently has a reverse gas baghouse installed for particulate control. This baghouse 

has 12 compartments, each with 64 bags approximately 33 feet in length and 11.5 inches in 

diameter. The design air to cloth ratio is approximately 2.0 with all compartments in service. 

A baghouse is a state-of-the-art technology for PM10 control for Healy 1. Other control 

technologies such as a mechanical collector, hot or cold electrostatic precipitators, or wet 

particulate scrubbers could be considered as additional feasible PM10 control options. 

However, none of these alternative technologies are considered to have the potential of 

matching the consistent PM10 removal performance of a baghouse. Therefore, the existing 

baghouse is considered BART for Healy 1, and completion of the five-step BART process is 

not required. 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-1 

4.0 BART Modeling Analysis 

4.1 Model Selection 

CH2M HILL used a Gaussian puff dispersion modeling system, Gaussian puff dispersion 

model (CALPUFF), to assess the visibility impacts of emissions from the BART sources at 

the GVEA Healy Power Plant at DNPP. 

The CALPUFF modeling system includes the Meteorological data preprocessing program 

for CALPUFF (CALMET) meteorological model CALPUFF with algorithms for chemical 

transformation and deposition, and a post processor capable of calculating concentrations, 

visibility impacts, and deposition (CALPOST). The CALPUFF modeling system was applied 

in a full, refined mode. Version numbers of the various programs in the CALPUFF system 

used by CH2M HILL were as follows: 

• CALMET Version 6.211, Level 060414 

• CALPUFF Version 6.112, Level 060412 

• CALPOST Version 6.131, Level 060410 

4.2 CALMET Methodology 

4.2.1 Dimensions of the Modeling Domain 

CH2M HILL used the CALMET model to generate a three-dimensional wind field and other 

meteorological parameters suitable for use by the CALPUFF model. A modeling domain 

was established to encompass the GVEA Healy Power Plant and allow for a 50-kilometer 

(km) buffer around DNPP. The modeling grid extends 550 kilometers in the east-west 

direction by 650 kilometers in the north-south direction which includes a 50 kilometer buffer 

around DNPP. Grid resolution is 2 km. Figure 4-1 shows the extent of the modeling domain. 

CH2M HILL followed the methodology outlined in the Western Regional Air Partnership 

(WRAP) CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for 

Class I Areas in Western United States (WRAP Protocol) (2006). The Mesoscale 

Meteorological Model, Version 5 (MM5) files used as input to CALMET were provided on 

the WRAP Website. 

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf

CH2M HILL used the Lambert Conformal Conic map projection for the analysis due to the 

large extent of the domain. 
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC FIGURE 4-1 Healy BART Modeling Domain GVEA Healy Power Plant 

-50

0

50

100150200250300350400450500550600650700

-250 -150 -50 50 150 250 350 45

X (km)

Y (km)
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

The default technical options listed in the WRAP Protocol current example CALMET.inp file 

were used for CALMET. Vertical resolution of the wind field included 11 layers, with 

vertical face heights as follows (in meters): 

• 0, 20, 100, 200, 350, 500, 750, 1000, 2000, 3000, 4000, 5000 

Other user-specified model options were set to values established by WRAP Regional 

Modeling Center (RMC) BART Protocol. Table 4-1 lists the key user-specified options used 

for this analysis. 

TABLE 4-1 

User-Specified CALMET Options 

GVEA Healy Power Plant 

CALMET Input Parameter Value 

CALMET Input Group 2 

Map Projection (PMAP) Lambert Conformal 

Longitude Origin -151 degrees 

Latitude Origin 59 degrees 

1st Standard Parallel 30 degrees 

2nd Standard Parallel 60 degrees 

X-Origin Offset -200 km 

Y-Origin Offset 0 km 

 Grid Spacing (DGRIDKM) 2 

Number of Grids 275 x 325 

Domain Extent 550 km x 650 km 

 Number Vertical Layers (NZ) 11 

 Top of Lowest Layer (m) 20 

 Top of Highest Layer (m) 5000 

CALMET Input Group 4 

 Observation Mode (NOOBS) 1 

CALMET Input Group 5 

 Prog. Wind Data (IPROG) 14 

 (RMAX1) 50 

 (RMAX2) 100 

 Terrain Influence (TERRAD) 10 

 (R1) 100 

 (R2) 200 

CALMET Input Group 6 

 Max Mixing ht (ZIMAX) 4500 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-4 

4.2.1.1 CALMET Input Data 

The CALMET model was run for 2002 only as recommended in the WRAP protocol for 

Alaska. CALMET inputs and scripts were obtained from the State and were used to recreate 

CALMET output. CALMET was run using the 15-km resolution 2002 MM5 data, surface 

meteorological observations from five sites and terrain and land use data. Table 4-2 lists 

the surface meteorological sites. Precipitation data were based on MM5 15-km output. 

MM5 precipitation was used instead of observed precipitation. 

TABLE 4-2 

CALMET Surface Stations 

GVEA Healy Power Plant 

Site ID LCC-X (km) LCC-Y (km) 

EDF 

(Elmendorf/Anchorage) 

26401 64.614 250.825 

PANC (Anchorage 

International Airport) 

26451 53.916 245.081 

VWS (Valdez/WSO) 26442 251.006 244.575 

ENA (Kenai Municipal 

Airport) 

26523 -12.782 175.868 

HOM (Homer Airport) 25507 -27.103 72.100 

4.3 CALPUFF Modeling Approach 

Methodologies for the BART control technology visibility improvement modeling were 

defined in the WRAP protocol. CALPUFF was run with the meteorological output from 

CALMET over the modeling domain described earlier. The CALPUFF model was used to 

predict visibility impacts for the baseline scenario for comparison to the predicted impacts 

for individual control options for GVEA Healy Power Plant. 

4.3.1 Background Ozone and Ammonia 

Hourly values of background ozone concentrations were used by CALPUFF for the 

calculation of SO2 and NOx transformation with the MESOPUFF II chemical transformation 

scheme. CH2M HILL obtained hourly ozone data for DNPP, Alaska, located within the 

modeling domain for 2002. 

For periods of missing hourly ozone data, the chemical transformation relied on a monthly 

default value of 40 parts per billion. Background ammonia was set to 0.1 parts per billion. 

Both of these background values were taken from the WRAP Protocol. 

4.3.2 Stack Parameters 

The stack parameters used for the baseline modeling reflect those that are in place under the 

current permit for GVEA Healy Power Plant. Individual control stack parameters reflect the 

anticipated changes associated with installation of the control technology alternatives that 

are being evaluated. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-5 

4.3.3 Emission Rates 

Modeling baseline emission rates for GVEA Healy Power Plant reflect peak 24-hour average 

emissions from the previous 12 month period, which may occur albeit rarely, under the 

source’s current permit with existing controls. Baseline emissions utilized for economic 

analyses represent a realistic depiction of anticipated annual emissions for the unit. 

CH2M HILL used available continuous emission monitoring data to determine the 

24-hour average actual emission rates. NOx and SO2 emissions were based on Continuous 

Emission Monitor (CEM) data from the highest emitting day in the one year period from 

May 1, 2007 to April 30, 2008. Emissions were modeled for SO2 and NOx. The model was run 

to include chemical transformation and calculated concentrations of nitric acid, nitrates, and 

sulfates. 

Individual control emission rates reflect the effects of the emissions control options under 

consideration. Modeled pollutants were the same as those listed for the pre-control scenario. 

4.3.4 Individual Control Scenarios 

Nine total individual control technologies for NOx and SO2 were evaluated. The selection of 

each control device was made based on the engineering analyses performed in Section 3. 

• NOx Option 0:Maintain Current Operation 

• NOx Option 1 :Optimize Existing Low NOx Burners with OFA 

• NOx Option 2: Replace OFA with ROFA 

• NOx Option 3: Replace OFA with ROFA and Rotomix 

• NOx Option 4: Low NOx Burner with OFA and SNCR System 

• NOx Option 5: Low NOx Burner with OFA and SCR System 

• SO2 Option 0:Maintain Current Operation 

• SOx Option 1: Increase Sodium Bicarbonate Feed Rate 

• SOx Option 2: Install Lime Spray Dryer FGD System 

• SOx Option 3: Install Wet Limestone FGD System 

Table 4-3 and Table 4-4 presents the stack parameters and emission rates used for the GVEA 

Healy Power Plant analysis for baseline and individual control modeling. Table 4-5 presents 

the stack parameters and emission rates for Auxiliary Boiler #1. In accordance with the 

WRAP Protocol, elemental carbon stack emissions and organic aerosol emissions were not 

modeled. 
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

TABLE 4-3 BART Model Input Data GVEA Healy Power Plant 

 Baseline NOX0 NOx1 NOx2 NOx3 NOx4 NOx5 SOX0 SO

Highest 

24 hour 

average 

peak 

Maintain 

Existing 

Low NOx

Burners 

with OverFire Air 

(OFA) 

Optimize 

Existing 

Low NOx

Burners 

with OverFire Air 

(OFA) 

Replace OFA 

with Rotating 

Opposed Fire 

Air (ROFA) 

Replace 

OFA with 

ROFA and 

Rotomix 

Low NOx

Burner with 

OFA and 

Selective 

Non-Catalytic 

Reduction 

(SNCR) 

System 

Low NOx

Burner with 

OFA and 

Selective 

Catalytic 

Reduction 

(SCR) System 

Existing Dry 

Sodium 

Bicarbonate 

Flue Gas 

Desulfurization 

(FGD) System 

(increase feed 

rate) 

Upgra

Sod

Bicarb

Flue 

Desulfu

(FGD) S

(increa

ra

SO2 StackEmissions (lb/hr) 

182.2 182.2 182.2 182.2 182.2 182.2 182.2 102.0 60

NOx Stack Emissions (lb/hr) 

151.0 85.0 77.7 50.7 35.5 63.0 24.0 151.0 15
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

TABLE 4-4 Stack Parameters and Emission Rates Healy Unit1 

Stack Parameters Unit 1a Baseline, All NOx, SOx0 and SOx1 SOx2 

Stack Height (feet) 122.0 122.0 Stack Height (meters) 37.2 37.2 Base Elevation (meters) 384.0 384.0 Base Elevation (feet) 1260 1260 Stack Exit Diameter (feet) 4.8 4.8 Stack Exit Diameter (meters) 1.5 1.5 Stack Exit Temperature (degF) 320 170 

Stack Exit Temperature (K) 433.2 349.8 Stack Exit Flow (acfm) 150,000 121,154 Stack Exit Area (square feet) 18.3 18.3 Stack Exit Velocity (feet per second) 136.5 110.3 Stack Exit Velocity (meters per second) 41.6 33.6 

aUnit 1 parameters derived from source tests and manufacturers data 
BART 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

TABLE 4-5 Stack Parameters and Emission Rates Auxiliary Boiler #1 

Stack Parameters Auxiliary Boilerb Auxiliary Boiler 

Stack Height (feet) 85 Stack Height (meters) 25.9 Base Elevation (meters) 384.0 Base Elevation (feet) 1260 Stack Exit Diameter (feet) 13.0 Stack Exit Diameter (meters) 3.96 Stack Exit Temperature (degF) 505Stack Exit Temperature (K) 450 Stack Exit Flow (acfm) 159,310 Stack Exit Area (square feet) 132.7 Stack Exit Velocity (feet per second) 20.0 Stack Exit Velocity (meters per second) 6.1 bAuxiliary Boiler parameters derived from WRAP Alaska BART analysis 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-9 

4.3.5 Modeling Process 

The CALPUFF modeling for the control technology options for GVEA Healy Power Plant 

followed this sequence: 

• Model pre-control (baseline) emissions 

• Model individual control scenario (if applicable) 

• Determine degree of visibility improvement 

• Model other control scenarios 

• Determine degree of visibility improvement 

• Factor visibility results into BART “five-step” evaluation 

4.3.6 Receptor Grids 

Discrete receptors for the CALPUFF modeling were placed at uniform receptor spacing 

along the boundary and in the interior of each area of concern. DNPP Class I area receptors 

were taken from the NPS database for Class I area modeling receptors. The TRC COORDS 

program was used to convert all latitude/longitude coordinates to Lambert Conformal 

Conic coordinates, including receptors, meteorological stations, and source locations. 

4.4 CALPOST 

The CALPOST processor was used to determine 24-hour average visibility results with 

output specified in deciview (dV) units. Calculations of light extinction were made for each 

pollutant modeled. The sum of all extinction values was used to calculate the delta-dV 

(∆dV) change relative to natural background. Default extinction coefficients for each 

pollutant, as shown below, were used. 

• Ammonium sulfate 3.0 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

CALPOST Visibility Method 6 was used to determine the visibility impacts. Monthly 

relative humidity factors were used in the light extinction calculations to account for the 

hygroscopic characteristics of nitrate and sulfate particles. The monthly relative humidity 

factors for DNPP as used by WRAP for Alaska are as follows: 

2.5, 2.3, 2.1, 1.9, 1.9, 2.2, 2.5, 3.0, 2.8, 2.9, 3.0, 3.1 

The natural background conditions as a reference for determining the ∆dV change 

represented the 20 percent best natural visibility days. The change in visibility impairment 

for the BART modeling is based on the increase in Haze Index from a BART-eligible source 

or sources relative to natural background, defined as the 20 percent best visibility days for 

each Class I area. This definition of natural background is consistent with the intent of the 

BART guideline (Federal Register Vol. 70, No. 128, pg 39125). 

Table 4-6 lists the annual average species concentrations from the WRAP protocol. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 4-10 

TABLE 4-6 

Average Natural Levels of Aerosol Components 

GVEA Healy Power Plant 

Aerosol Component 

Average Natural Concentration 

(micrograms per cubic meter) for DNPP 

Ammonium Sulfate 0.12 

Ammonium Nitrate 0.10 

Organic Carbon 0.47 

Elemental Carbon 0.02 

Soil 0.50 

Coarse Mass 3.00 

Note: Taken from WRAP RMC Alaska Modeling files 

4.5 Presentation of Modeling Results 

This section presents the results of the CALPUFF visibility improvement modeling analysis 

for GVEA Healy Power Plant. 

4.5.1 Degree of Visibility Change for Baseline vs. Preferred Scenario 

CH2M HILL modeled the GVEA Healy Power Plant for the baseline and nine individual 

control scenarios. The individual control scenarios included emission rates for SO2 and NOx,

which may be possible if BART controls were optimized or installed on the GVEA Healy 

Power Plant. 

The visibility results for DNPP are presented in Table 4-7. In addition, results for Auxiliary 

Boiler #1 are also given in Table 4-8. 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 

TABLE 4-7 Costs and Visibility Modeling Results for Baseline Vs. Individual Control Scenarios GVEA Healy 1 

Scenario First Year Cost 

Highest Delta-Deciview 

(ΔdV) No. of Days Above 0.5 dV Cost per dV Reduction 

Baselinea 3.359 136 NOx Option 0: Existing Low NOx Burners with OFA $0b 2.828 97 $0 

NOx Option 1 :Optimize Existing Low NOx Burners with OFA $2,337 2.799 93 $4,173 

NOx Option 2: Replace OFA with ROFA $672,997 2.688 80 $1,002,976 

NOx Option 3: Replace OFA with ROFA and Rotomix $1,094,835 2.623 69 $1,487,548 

NOx Option 4: Low NOx Burner with OFA and SNCR system $418,810 2.739 85 $675,500 

NOx Option 5: Low NOx Burner with OFA and SCR system $1,263,251 2.573 65 $1,607,190 

SOx Option 0: Dry Sodium Bicarbonate FGD System $0b 3.195 111 $0 

SOX Option 1: Increase Dry Sodium Bicarbonate FGD 

System (increase feed rate) $758,322 3.109 97 $3,033,288 

SOX Option 2: Install Lime Spray Dryer FGD System $1,607,872 4.229 116 -$1,848,129 

SOX Option 3: Install Wet Limestone FGD System $2,659,104 4.519 118 -$2,292,331 

aBaseline is defined as current operation values with the highest 24-hr average for the modeling analysis and ($0) for the economic analysis bThere are no costs referenced for existing operations for economic purposes although in reality there are significant operation and maintenance costs associated with the curreTABLE 4-8 Visibility Results for Auxiliary Boiler #1 

Scenario Pollutant Controlled 1st High delta Deciview 8th High delta Deciview 

Baseline none 0.067 0.02 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-1 

5.0 Preliminary Assessment and 

Recommendations 

As a result of the completed technical and economic evaluations, and in consideration of 

potential environmental impacts from implementation of potential controls, and the 

modeling analysis completed for Healy 1, as well as consideration of the existing 

information documenting no detectable visibility impairment at DNPP from current 

operations, existing controls are considered BART.

The evaluation of visibility improvements for all emission control scenarios discussed were 

analyzed, and the results are compared in the sections below, utilizing a Least-Cost 

Envelope, as outlined in the draft EPA (1990) New Source Review Workshop Manual. 

5.1 Least-Cost Envelope Analysis 

The total annualized cost, cost per dV reduction, and cost per reduction in number of days 

above 0.5 dV for the control options modeled in Section 4 to determine the visibility impact 

on the Class 1 area, DNPP, are listed in Table 5-1. A comparison of the incremental costs 

between relevant options is shown in Table 5-2. The total annualized cost versus number of 

days above 0.5 dV and the total annualized cost versus ΔdV reduction are shown in 

Figures 5-1 and 5-2 for the Class I area. 

All modeling results utilize a baseline determined by the highest 24 hour average emission 

rate over the previous 12-month period. Comparing the modeling results from the 

anticipated emissions rate with existing controls versus the highest 24 hour average 

emission rate, there is a resultant visibility improvement demonstrated. Visibility 

improvement due to NOx is quantified as a 39 day reduction in average number of days 

above 0.5 dV, while the SO2 improvement is a 25 day reduction in average number of days 

above 0.5 dV. Since there is no additional cost to continue current operation with the 

existing NOx and SO2 controls, the “Option 0” scenarios shown in Table 5-1 below are listed 

at zero cost. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-2 

5.1.1 Analysis Methodology 

Page B-41 of the New Source Review Manual, EPA states that “Incremental cost-effectiveness 

comparisons should focus on annualized cost and emission reduction differences between 

dominant alternatives. Dominant sets of control alternatives are determined by generating 

what is called the envelope of least-cost alternatives. This is a graphical plot of total 

annualized costs for a total emissions reductions for all control alternatives identified in the 

BART analysis...” 

An analysis of incremental cost effectiveness has been conducted. This analysis was 

performed in the following way: 

• First, the control option scenarios are expressed per day and per dV reduction, represent 

a comparison of the different control options, and are summarized in Tables 5-1 and 

5-2 for the Class I area. 

TABLE 5-1 

Class I Area Summary of Control Performance 

GVEA Healy 1 

Optionsa

Highest dV 

Reduction 

Reduction in 

Average 

Number of 

Days Above 0.5 

dV (Days) 

Total 

Annualized 

Cost 

($million) 

Cost per dV 

Reduction 

($million/dV 

Reduced) 

Cost per Reduction 

in No. of Days 

Above 0.5 dV 

($million/Day 

Reduced) 

NOX Option 0 :Existing Low NOx 

burners with over-fire air (OFA)b 0.531 39 $0b

 $0b $0b

NOx Option 1 :Optimize Existing Low 

NOx Burners with OFA 0.560 43 $0.0023 $0.0042 $0.0001 

NOx Option 2: Replace OFA with 

ROFA 0.671 56 $0.6730 $1.0030 $0.0120 

NOx Option 3: Replace OFA with 

ROFA and Rotomix 0.736 67 $1.0948 $1.4875 $0.0163 

NOx Option 4: Low NOx Burner with 

OFA and SNCR System 0.620 51 $0.4188 $0.6755 $0.0082 

NOx Option 5: Low NOx Burner with 

OFA and SCR System 0.786 71 $1.2633 $1.6072 $0.0178 

SOX Option 0: Existing dry sodium 

bicarbonate flue gas desulfurization 

(FGD) systemb

0.164 25 $0b

 $0b $0b

SOx Option 1: Upgrade Dry Sodium 

Bicarbonate FGD System (increase 

feed rate) 

0.250 39 $0.7583 $3.0333 $0.0194 

SOx Option 2: Install Lime Spray 

Dryer FGD Systemc -0.870 20 $1.6079 -$1.8481 $0.0804 

SOx Option 3: Install Wet Limestone 

FGD Systemc -1.160 18 $2.6591 -$2.2923 $0.1477 

a

Baseline is defined as current operation values with the highest 24-hr average for the modeling analysis and ($0) for the 

economic analysis. All options are compared to baseline. 

b

There are no costs referenced for existing operations for economic purposes although in reality there are significant operation and 

maintenance costs associated with the current operations. 

c

Visibility impacts are greater with this option because of lower plume rise resulting from colder and wetter plume 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-3 

• Then the most reasonable smooth curve of least-cost control option scenarios is plotted 

for each analysis. Figures 5-1 and 5-2 present the two analyses (cost per dV reduction 

and cost per reduction in number of days above 0.5 dV) for the Class 1 area impacted by 

the operation of Healy 1. 

In Figures 5-1 and 5-2 control options for NOx are compared as a graph of total annualized 

cost versus number of days above 0.5 dV and delta deciview reduction. The EPA states that 

“In calculating incremental costs, the analysis should only be conducted for control options 

that are dominant among all possible options.” In Figure 5-1, the dominant control options 

include Option 0 (Existing LNB and OFA), Option 1 (Optimize LNB and OFA), and Option 

4 (SNCR) as depicted on the least-cost envelope. All other options are to the left of the curve 

and therefore are inferior options. Remaining options should not be considered in the 

derivation of incremental cost effectiveness. SNCR has the potential of removing an 

incrementally small amount of additional NOx for a significantly higher cost. Option 5 (SCR) 

offers the greatest potential for visibility improvement, however the high first year cost of 

over $1.2 million would impact the ultimate cost of generation for Healy 1. Currently, the 

interior is in an energy crisis and the increased cost to GVEA membership would be 

significant. 

The least-cost envelope analysis was also completed for SO2 emissions, with results shown 

on Figures 5-3 and 5-4. The dominant SO2 control is the continuation of current operations 

of the existing sodium bicarbonate injection system. Also as shown in Table 5-2 below, the 

installation of a lime spray dryer or wet limestone scrubber results in an increase in Δdv 

impact due to a lower flue gas temperature with these technologies (less plume rise). 

Table 5-3 below provides a comparison of the tons of NOx and SO2 removed versus total 

annual cost on a rounded basis.
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-4 

TABLE 5-2 

Class I Area Incremental Data 

GVEA Healy 1 

Options Compareda

Incremental 

Reduction in 

Days Above 

0.5 dV (Days) 

Incremental 

dV Reductions 

(dV) 

Incremental Cost 

Effectiveness 

($/dV) 

Incremental Cost Effectiveness 

($/Days) 

NOX Option 0 :Existing Low 

NOx burners with over-fire air 

(OFA)b

39 0.531 $0b

 $0b

NOx Option 1 :Optimize 

Existing Low NOx Burners 

with OFA 

43 0.560 $80,586 $584 

NOx Option 2: Replace OFA 

with ROFA 

56 0.671 $6,041,982 $51,589 

NOx Option 3: Replace OFA 

with ROFA and Rotomix 

67 0.736 $6,489,815 $38,349 

NOx Option 4: Low NOx

Burner with OFA and SNCR 

System 

51 0.620 $5,827,802 $52,059 

NOx Option 5: Low NOx

Burner with OFA and SCR 

System 

71 0.786 $5,086,994 $42,222 

SOX Option 0: Existing dry 

sodium bicarbonate flue gas 

desulfurization (FGD) systemb

25 0.164 $0b $0b

SOx Option 1: Upgrade Dry 

Sodium Bicarbonate FGD 

System (increase feed rate) 

39 0.250 $8,817,698 $54,166 

SOx Option 2: Install Lime 

Spray Dryer FGD System 

20 -0.870 -$758,527 -$44,713 

SOx Option 3: Install Wet 

Limestone FGD System 

18 -1.160 -$3,624,938 -$525,616 

a

Baseline is defined as current operation values with the highest 24-hr average for the modeling analysis and ($0) for the 

economic analysis. All options are compared to baseline. 

b

There are no costs referenced for existing operations for economic purposes although in reality there are significant 

operation and maintenance costs associated with the current operations. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-5 

FIGURE 5-1 

Least Cost Envelope Compared to Baseline 

GVEA Healy 1 NOx Options 

$0.0000

$0.2000

$0.4000

$0.6000

$0.8000

$1.0000

$1.2000

$1.4000

0 10 20 30 40 50 60 70 80

Reduction in Days of Exceeding 0.5 dv (days)

Total Annualized Cost (Mil $)

FIGURE 5-2 

Least Cost Envelope Compared to Baseline 

GVEA Healy 1 NOx Options 

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90

Highest Delta-Deciview Reduction (dv)

Total Annualized Cost (Mil $)
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-6 

FIGURE 5-3 

Least Cost Envelope Compared to Baseline 

GVEA Healy 1 SO2 Options 

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

0 5 10 15 20 25 30 35 40 45

Reduction in Days of Exceeding 0.5 dv (days)

Total Annualized Cost (Mil $)

FIGURE 5-4 

Least Cost Envelope Compared to Baseline 

GVEA Healy 1 SO2 Options 

$0.00

$0.20

$0.40

$0.60

$0.80

0.00 0.05 0.10 0.15 0.20 0.25 0.30

Highest Delta-Deciview Reduction (dv)

Total Annualized Cost (Mil $)
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-7 

Figure 5-5 and Figure 5-6 below graphically depicts information from Table 5-3 above, and 

presents the annual tons of NOx and SO2 removed versus the total annual cost. 

TABLE 5-3 

Annual Cost and Tons Removed Based on Current Operating Values 

GVEA Healy 1 

Options 

Total Annual Cost 

(Rounded) Tons Removed 

NOx Option 0: Existing Low NOx Burners w/OFAa See Note a See Note a 

NOx Option1 Optimize Existing Low NOx Burners w/ OFA $2,000 30 

NOx Option 2: Replace OFA w/ ROFA $400,000 92 

NOx Option 3: Replace OFA w/ ROFA & Rotomix $700,000 148 

NOx Option 4: Low NOx Burner w/ OFA & SNCR System $1,100,000 214 

NOx Option 5: Low NOx Burner w/ OFA & SCR System $1,300,000 266 

SO2 Option 0: Dry Sodium Bicarbonate FGD System See Note a See Note a 

SO2 Option 1: Upgrade Dry Sodium Bicarbonate FGD 

System (increase feed rate) $800,000 177 

SO2 Option 2: Install Lime Spray Dryer FGD System $1,600,000 222 

SO2 Option 3: Install Wet Limestone FGD System $2,700,000 340 

a

There are no costs referenced for existing operations (Option 0) for economic purposes because all costs and 

evaluations are compared to Option 0. In reality there are significant operation and maintenance costs 

associated with the current operations. 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-8 

FIGURE 5-5 

Additional Annual cost versus Additional Tons Removed Compared to Existing Operations 

GVEA Healy 1 NOx Options 

0

200000

400000

600000

800000

1000000

1200000

1400000

0 50 100 150 200 250 300

Tons NOx Removed

Total Annual Cost

FIGURE 5-6 

Additional Annual cost versus Additional Tons Removed Compared to Existing Operations 

GVEA Healy 1 SO2 Options 

0

500000

1000000

1500000

2000000

2500000

3000000

0 50 100 150 200 250 300 350 400

Tons SO2 Removed

Total Annual Cost
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-9 

5.1.2 Analysis of Results 

Analysis of the results for the DNPP from the tables and figures above supports the 

conclusions stated below. While the greatest reduction in dV and number of days above 

0.5 dV is achieved with NOx Option 5 (SCR) and SO2 Option 1 (Upgrade dry sodium 

bicarbonate FGD system), these options are not the selected alternatives. As discussed above 

in Section 5.1.1, utilizing the least-cost curve analyses incorporates economic considerations 

of all alternatives and results in the conclusions presented below in Section 5.2. 

5.2 BART Conclusions 

5.2.1 NOx Emission Control 

The optimization of existing LNB w/OFA through the utilization of a boiler consultant 

while shown to be the most effective of the new control options evaluated will not have a 

measurable improvement to visibility in DNPP. Any increase in CO emissions would be an 

undesirable environmental effect of implementation of this option. 

Since there is only an estimated 0.03 dV improvement between Option 1 and Option 0, and 

this difference is non-perceivable by the human eye maintaining current operation of the 

existing NOx controls are considered to be BART for Healy 1. 

5.2.2 SO2 Emission Control 

Even though increasing the sodium bicarbonate injection rate while utilizing the existing 

sorbent injection system was shown to be the most effective of the new control options 

evaluated, implementation will not have a measurable improvement to visibility in DNPP. 

An increase in mercury emissions and possible occurrence of a brown cloud would be 

undesirable environmental effects of implementation of this option. 

Since there is only an estimated 0.09 dV improvement between Option 1 and Option 0, and 

this difference is non-perceivable by the human eye, maintaining current operation of the 

existing SO2 controls are considered to be BART for Healy 1 

5.2.3 PM10 Emission Control 

The existing fabric filter is considered BART for Healy 1. 

5.2.4 Auxiliary Boiler # 1 

Emissions and impacts from Auxiliary Boiler #1 are insignificant, and no controls are 

concluded as BART for this unit. 

5.3 Just-Noticeable Difference in Atmospheric Haze 

Conclusions reached in the reference document “Just-Noticeable Differences in Atmospheric 

Haze” by Dr. Ronald Henry state that only dV differences of approximately 1.5 to 2.0 dV or 

more are perceivable by the human eye. Deciview changes of less than 1.5 cannot be 

distinguished by the average person.. Therefore, the modeling analysis results indicate that 

based on the above, no observable visibility improvements at DNPP would be expected 
BART ANALYSIS FOR HEALY POWER PLANT 

GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 5-10 

under any of the control options, since maximum modeled improvement for any control 

technology is only 0.5dV (for installation of SCR). 

5.4 Recommendations 

As summarized in the sections above, maintaining operation of the existing controls are 

considered BART for Healy 1.

Because the NOx and SO2 BART selections result in minimal visibility improvement, there 

will likely not be any perceptible difference (from just-noticeable-difference discussion 

above) in DNPP. Previous visibility studies have concluded that actual visibility impairment 

at DNPP from Healy has not been detected by trained NPS observers. 
GOLDEN VALLEY FINAL BART REPORT 01_02_09.DOC 6-1 

6.0 References 

EPA. 1990. New Source Review Workshop Manual –Prevention of Significant Deterioration 

Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations; 

Final Rule (40 CFR Part 51; July 6, 2005, pg 39129) 

Henry, Ronald C. 2002. “Just-Noticeable Differences in Atmospheric Haze.” Journal of the Air 

and Waste Management Association 52:1238-1243. October 2002 

WRAP. 2006. Draft Final Modeling Protocol, CALMET/CALPUFF Protocol for BART Exemption 

Screening Analysis for Class I Areas in the Western United States. Air Quality Modeling Forum. 

Regional Modeling Center. August 15, 2006.